Methods for mapping power generation installations

ABSTRACT

Various implementations described herein are directed to a method for recording, by a device, identifying information of a plurality of components of a photovoltaic (PV) installation. The method may record, by the device, at least one of timestamps or locations corresponding to each component of the plurality of components. The method may generate, based on the identifying information, timestamps, and locations, a map of the PV installation.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. provisional patentapplication Ser. No. 62/303,017, filed Mar. 3, 2016, entitled “Methodsfor Mapping Power Generation Installations,” and U.S. provisional patentapplication Ser. No. 62/381,298, filed Aug. 30, 2016, entitled “Methodsfor Mapping Power Generation Installations,” which are both herebyincorporated by reference in their entirety.

BACKGROUND

Photovoltaic (PV) installations may include a large number of componentsand wide variety of devices. A PV installation may include one or morearrays of PV generators (e.g. solar modules, solar cells, solar panels),one or more inverter(s), communication devices, and PV power devicessuch DC/DC converters, DC-AC microinverters, combiner boxes, andMaximum-Power-Point-Tracking (MPPT) devices. Some installations mayfurther include batteries. Some of the electronic modules may beintegrated with the PV modules and may provide other functions such asmonitoring of performance and/or protection against theft. In case ofthe system experiencing power loss or in case of a potentially unsafecondition, it may be desirable for a system maintenance operator tophysically locate a particular device (e.g. solar panel, DC-DC converteror micro-inverter) that may be potentially responsible for the powerloss or potentially unsafe condition.

Operators and monitoring bodies of PV installations might not alwayshave access to a map which indicates the location of each PV module,identified by a serial number. In such cases, troubleshooting problemsmay be time consuming, since locating a specific module, e.g., amalfunctioning module, may be difficult. In other instances, a map ofthe installation may be obtained by significant manual effort, such as amaintenance worker walking through the installation and copying IDnumbers off modules, denoting their location on a map. If performedmanually, human error may also cause inaccurate information to berecorded in the maps.

There is a need for an automatic or semi-automatic method of generatingphysical maps of PV installations, to save work and reduce errors, whileallowing system monitoring personnel to obtain the benefits of having amap which indicates the locations and ID numbers of PV modules.

SUMMARY

The following summary is a short summary of some of the inventiveconcepts for illustrative purposes only, and is not intended to limit orconstrain the inventions and examples in the detailed description. Oneskilled in the art will recognize other novel combinations and featuresfrom the detailed description.

Embodiments herein may employ methods for generating maps of PVinstallations. Some illustrative embodiments may be fully automatic, andsome may require manual steps.

In illustrative methods, a suitable localization algorithm may beutilized to measure or estimate the global coordinates of photovoltaic(PV) devices, and/or the distance and/or angle between differentdevices, and/or the distance and/or angle between devices and knownlocations. Some embodiments may include obtaining the global coordinatesof devices. Some embodiments may produce a map displaying the physicalplacement and location of devices along with identifying information(e.g. ID or serial numbers). Some embodiments may utilize high-accuracyGlobal Positioning System (GPS) technology to map the installation. Forexample, some illustrative methods may include scanning an identifyingbarcode on PV devices while using GPS to obtain the global coordinatesat each scanned location. In some embodiments, a map not includingidentifying module information may be further utilized to match specificmodules to the measured GPS coordinates. Some embodiments may include PVdevices transmitting and receiving wireless signals from one another,and using measured or estimated quantities such as Received SignalStrength Indication (RSSI), Angle of Arrival (AOA, also known asDirection of Arrival, or DOA) and/or Time Difference of Arrival (TDOA)to estimate relative distances and/or angles between modules. In someembodiments, Power Line Communication (PLC) methods may be used alongwith Time Domain Reflection (TDR) techniques to estimate the location ofa set of PV devices within a PV installation. The set of estimates maybe processed to obtain an accurate physical map of the installation,including identifying where each PV module and/or PV device isphysically located.

In other illustrative methods, photovoltaic modules may be operated toincrease and decrease the electrical power produced by the photovoltaicmodules, which may result in a change of temperature at the photovoltaicmodules. A thermal imaging device may be used to capture thermal imagesof a group of photovoltaic modules under different power production andtemperature conditions, and suitable methods may analyze and aggregatethe thermal images to obtain an accurate physical map of theinstallation.

As noted above, this summary is merely a summary of some of the featuresdescribed herein. It is not exhaustive, and it is not to be a limitationon the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentdisclosure will become better understood with regard to the followingdescription, claims, and drawings. The present disclosure is illustratedby way of example, and not limited by, the accompanying figures. A morecomplete understanding of the present disclosure and the advantagesthereof may be acquired by referring to the following description inconsideration of the accompanying drawings, in which like referencenumbers indicate like features, and wherein:

FIG. 1 is a flow diagram of a method for generating a photovoltaic (PV)installation map according to one or more illustrative aspects of thedisclosure.

FIG. 2A is a flow diagram of a method for fitting measured locations toa map according to one or more illustrative aspects of the disclosure.

FIG. 2B illustrates a non-identifying map (NIM) according to one or moreillustrative aspects of the disclosure.

FIG. 2C illustrates an estimated layout map (ELM) according to one ormore illustrative aspects of the disclosure.

FIG. 2D illustrates how illustrative methods may be applied toillustrative PV systems according to one or more illustrative aspects ofthe disclosure.

FIG. 3A is a flow diagram of a method for generating an installation mapbased on time and location according to one or more illustrative aspectsof the disclosure.

FIG. 3B is a flow diagram of a method for mapping samples to stringsaccording to one or more illustrative aspects of the disclosure.

FIG. 4 illustrates an illustrative of representing and storing aNon-Identifying Map according to one or more illustrative aspects of thedisclosure.

FIG. 5A is a flow diagram of a method for generating a Non-IdentifyingMap according to one or more illustrative aspects of the disclosure.

FIG. 5B illustrates a user interface for PV installation mappingaccording to one or more illustrative aspects of the disclosure.

FIG. 6 illustrates an illustrative embodiment of reading identifyinginformation from a PV device and estimating the device locationaccording to one or more illustrative aspects of the disclosure.

FIG. 7 illustrates illustrative devices which may be used for readingidentifying information and/or estimating device location according toone or more illustrative aspects of the disclosure.

FIG. 8A is a flow diagram of a method for installation mapping accordingto one or more illustrative aspects of the disclosure.

FIG. 8B illustrates results of various stages of installation mappingaccording to one or more illustrative aspects of the disclosure.

FIG. 9 is part-block diagram, part schematic of an illustrative PVinstallation that may be mapped according to one or more illustrativeaspects of the disclosure.

FIG. 10 is a flow diagram of a method for grouping power devices intogroups according to one or more illustrative aspects of the disclosure.

FIG. 11A is a part-block diagram, part-schematic of PV system componentswhich may be used in conjunction with methods described herein.

FIG. 11B is a schematic of illustrative variable impedance circuitsaccording to one or more illustrative aspects of the disclosure.

FIG. 12 illustrates an illustrative form of a wave reflected off atransmission line according to one or more illustrative aspects of thedisclosure.

FIG. 13 is a flow diagram of a method for testing power devicesaccording to one or more illustrative aspects of the disclosure.

FIG. 14 is a part-block diagram, part-schematic of a PV arrangement,comprising PV system components, which may be used in conjunction withmethods described herein.

FIG. 15A is a part-block diagram, part-schematic of a PV panel and PVsystem components which may be used in conjunction with methodsdescribed herein.

FIG. 15B is a part-block diagram, part-schematic of PV system componentswhich may be used in conjunction with methods described herein.

FIG. 16 is a flow diagram of a method for grouping power devices intostrings according to one or more illustrative aspects of the disclosure.

FIG. 17A illustrates an illustrative PV string of PV devices accordingto one or more illustrative aspects of the disclosure.

FIG. 17B illustrates an illustrative current leakage circuit accordingto one or more illustrative aspects of the disclosure.

FIG. 18 is a flow diagram of a method for determining the order of powerdevices within a PV string according to one or more illustrative aspectsof the disclosure.

FIG. 19 illustrates illustrative devices which may be used for readingidentifying information and/or estimating device location according toone or more illustrative aspects of the disclosure.

FIG. 20 illustrates a thermal image of a group of photovoltaic modulesaccording to one or more illustrative aspects of the disclosure.

FIG. 21 is a flow diagram of a method for determining relative locationsof one or more PV modules within a group of PV modules according to oneor more illustrative aspects of the disclosure.

DETAILED DESCRIPTION

In the following description of various illustrative embodiments,reference is made to the accompanying drawings, which form a parthereof, and in which is shown, by way of illustration, variousembodiments in which aspects of the disclosure may be practiced. It isto be understood that other embodiments may be utilized and structuraland functional modifications may be made, without departing from thescope of the present disclosure.

Monitoring of PV installations may include data collected by a centralcontrol system which monitors the power output by the PV installationand identifies potentially problematic operating conditions or safetyhazards. When the installation experiences power loss, it may bedesirable to ascertain whether it is due to environmental conditions orfrom malfunctions and/or poor maintenance of the components of the PVinstallation. Furthermore, it may be desirable to easily physicallylocate the particular module (e.g. solar panel, DC-DC converter ormicro-inverter, combiner box) that may be responsible for the powerloss. A map of the PV installation which displays the physical locationof the various PV modules or devices (identified by ID numbers, forexample) comprising the installation may assist in rapid location of thedesired module and fast resolution of the problem. For example, in caseof a decrease in the power output by a PV panel, a power device coupledto the panel may send information to a centralized control unitreporting the loss of power. The information may be transmitted usingpower line communications, wireless communication, acousticcommunication or other protocols, and may include the ID number of thePV device. If the low power output persists, a maintenance worker mayneed to physically go to the underperforming panel and investigate thereason behind the low power.

A Physical Identification Map (PIM) may refer to a physical mapindicating the location of modules within a photovoltaic (PV)installation, including attaching identifying information such as serialor ID numbers to some or all of the modules displayed in the map. ANon-Identifying Map (NIM) may refer to a map that describes the locationof modules but does not identify a specific module at each location.

FIG. 1 is a flow diagram of a method for generating a PV installationmap according to one or more illustrative aspects of the disclosure. Inone or more embodiments, the method of FIG. 1, or one or more stepsthereof, may be performed by one or more computing devices or entities.For example, portions of the method of FIG. 1 may be performed bycomponents of a computer system. The method of FIG. 1, or one or moresteps thereof, may be embodied in computer-executable instructions thatare stored in a computer-readable medium, such as a non-transitorycomputer-readable medium. The steps in the method of FIG. 1 might notall be performed in the order specified and some steps may be omitted orchanged in order.

At step 100, an initial map of a PV installation layout may be created.The initial map may be a physical map. For example, at step 100,measured Global Positioning System (GPS) coordinates may be used tomatch modules to physical locations on a PIM. The initial map may becreated and represented in various ways. In one implementation, theinitial map may be represented as a text file which includes informationregarding the number of devices, the number of rows, the distancesbetween devices, the distances between rows, or any other informationrelevant to the physical layout of the installation. In anotherimplementation, the basic map may be automatically generated byinstallation-design software, and the layout information may be encodedin a digital file generated by the installation-design software.

In some embodiments, step 100 might not be performed. For example, step100 might not be performed if there is high enough accuracy in othersteps of the method to compensate for the lack of an initial map.

In steps 110-13, power modules in the PV installation may be scanned.For example, the power modules may be scanned by rows. At step 110 eachdevice in a row of the PV installation may be scanned. The scanning maybe carried out using a locating device that combines scanningcapabilities with a GPS receiver. The locating device may furtherinclude one or more of a clock, memory, communication means and aprocessing unit. Scanning may comprise utilizing a barcode reader toread a barcode which is attached to the module being scanned (e.g. abarcode on a sticker which is stuck to the module), utilizing a camerato identify serial numbers, obtaining identifying information from anRFID tag, or any combinations thereof. The locating device may be asmartphone running an application which combines barcode reading orserial number identifying with GPS localization. The scanning maycomprise taking a picture of an identifying element of the module (e.g.an identification sticker) which can later be processed to identify themodule based on the picture. In some embodiments, in step 111 the usermay conFig. the device (e.g. by press of a button) at the start of eachrow to begin logging a row of the installation. In some embodiments, thelocating device may use time or spatial differences between scans todetermine when a new row is being scanned. For example, if a timebetween scans is above a certain threshold, the locating device maydetermine that a new row is being scanned.

At step 112 each PV device in the current row may be scanned. Each timea device is scanned, the module's identifying information (e.g. barcode,ID number, picture, RFID tag) as well as the GPS coordinates of thelocating device at the time of scanning may be logged and stored intomemory. The identifying information corresponding to a device may beunique. A timestamp of the time of scanning may also be logged orstored.

At step 113 it may be determined if all rows of the installation havebeen scanned. For example, it may be determined if all rows within aspecified area have been scanned. If all rows have been scanned, themethod may proceed to step 120. Otherwise, steps 110-13 may be repeated.Steps 110-13 may be repeated until all rows of the installation, or alldevices within the installation, have been scanned.

At step 120, the data (e.g. coordinates, timestamps) collected duringsteps 110-13 may be collected and input to a matching algorithm. The mapcreated in step 100 may also be input to the matching algorithm.

At step 130, the matching algorithm may be run by an appropriatecomputing device, such as a computer, server, DSP, microcontroller, ASICor FPGA. The algorithm may use the inputted data and/or the map todetermine which PV module is located at each of the locations indicatedon the map. FIG. 2A, further described below, is an example of a methodthat may be used by a matching algorithm at step 130.

At step 140, the matching algorithm may generate, based on the inputreceived at step 120, a map of the PV installation. The map may compriseone or more module identifiers. The module identifiers may be associatedwith a location in the map. For example, the algorithm may output a mapwith module identification information being displayed at each module'slocation. The map may be physically printed onto a sheet of paper, orviewed on an appropriate electronic device such as a computer monitor,tablet or smartphone.

FIG. 2A is a flow diagram of a method for fitting measured locations toa map according to one or more illustrative aspects of the disclosure.In one or more embodiments, the method of FIG. 2A, or one or more stepsthereof, may be performed by one or more computing devices or entities.For example, portions of the method of FIG. 2A may be performed bycomponents of a computer system. The method of FIG. 2A, or one or moresteps thereof, may be embodied in computer-executable instructions thatare stored in a computer-readable medium, such as a non-transitorycomputer-readable medium. The steps in the method of FIG. 2A might notall be performed in the order specified and some steps may be omitted orchanged in order.

At step 131, a map and/or GPS coordinates may be received. For example,the map and/or GPS coordinates may be loaded from memory. The map and/orGPS coordinates may have been measured when scanning PV modules. Thereceived map may comprise a non-identifying map (NIM), which might notinclude identifying module information.

At step 132, the GPS measurements may be grouped into rows. In someembodiments, the grouping into rows may be done while scanning one ormore modules. For example, a scanning operator may press a reset buttonwhen beginning to scan, or prior to scanning, each row. In someembodiments, the grouping of measurements into rows may be carried outby a computer algorithm, using methods further described herein. Thegrouping of measurements into rows may be helpful, for example, when thePIM is generated using an NIM, which already indicates the number ofrows and the length of each row. In embodiments in which the PIM isgenerated without benefit of a pre-existing NIM, the grouping into rowsmay allow for filtering of measurement noise. For example, filtering, orreduction, of measurement noise may be performed by determining thestandard distance and angle between adjacent panels in a same row. Steps133-37 may be performed iteratively, until the first row of scannedsamples has been considered as a candidate to represent each row of theinstallation. At step 133, a row is selected from the NIM. At step 134,the first row of location measurements may be fit to the selected row.At step 135, having fit the first row of location measurements to theselected row, the other rows of measured samples may be fit to the otherrows of the NIM, using “snap to grid” or similar methods. In someembodiments, attempted fitting of the other rows of measured samples tothe other NIM rows may be carried out multiple times, using multiple roworientations, before an optimal fitting (by an appropriate criterionsuch as Least Squares) is selected.

At step 136, a total fitting error may be calculated. The total fittingerror may be based on the estimated locations of each device and/or thelocations indicated by the NIM. Estimated individual errors of eachdevice may be aggregated by an appropriate criterion, such as Sum ofSquares. The selected fitting and resultant aggregated error may bestored. For example, the selected fitting and resultant aggregated errormay be stored in an appropriate memory device.

At step 137, the method may determine if all NIM rows have beenconsidered as the row represented by the first row of measurements. Ifsome NIM rows have not been considered the method may loop back to step134. For example, the NIM rows that have not been considered may becandidates for consideration in later iterations. If it is determined,at step 137, that all NIM rows have been considered, the method mayproceed to step 138.

At step 138, one or more aggregated errors calculated and stored at step136 may be compared to one another to select a fitting. In oneimplementation, a fitting corresponding to the minimum aggregated errormay be selected. Other factors may be considered at step 138.

At step 139, the fitting selected at step 138 may be output,transforming the NIM to a PIM that includes the fitting selected at step138. In some embodiments, steps 134-37 may be modified such that insteadof fitting the first row of measurements to each row in the NIM, eachrow of measurements is fitted to a certain row of the NIM (for example,the first row of the NIM).

Reference is now made to FIGS. 2B and 2C, which depict illustrativeexamples of a PV installation which may be mapped according toillustrative embodiments. FIG. 2B illustrates a Non-Identifying Map(NIM) 215 that may be generated, using methods described herein, toreflect a layout of the PV installation. FIG. 2C illustrates anEstimated Layout Map (ELM) 217 of the installation, which may beobtained using methods described herein to estimate the absolutelocations of PV devices or the locations with regard to one another.FIGS. 2B and 2C may correspond to a same PV installation.

In FIGS. 2B-D, the illustrated squares may correspond to devicelocations according to the NIM, and the circles may correspond to devicelocations according to measured data corresponding to the devices. Incertain instances, the PV system may be of a non-symmetric layout. Forexample, in the NIM 215, one row has two fewer devices than the othertwo rows. In certain instances, because of measurement inaccuraciesand/or noise, an ELM, such as the ELM 217, may contain inaccuracies.

Reference is now made to FIG. 2D, which illustrates aspects of steps134-36, described above in FIG. 2A, as applied to the PV systemillustrated in FIGS. 2B-C. In Fitting A, at step 133, the first row ofthe NIM is selected. At step 134, the first row of location measurementsis fit to the selected first row of the NIM, and at step 135 theremaining two rows are fit to the NIM in a way that minimizes the totalmismatch between the NIM-devices (depicted as squares) and the ELMdevices (depicted as circles). At step 136, the total fitting error iscalculated. Different error measures may be considered. For example, asum-of-squares error measure may be considered. If, for example, threedevices are estimated to be at the following locations along theXY-plane: (0,0), (1,0) and (2,0), while according to the NIM the threedevices are actually located at (0,0.5), (1, 1.5) and (2,0), the squareof the estimation error for the first device will be(0-0)²+(0-0.5)²=0.25. Similarly, the squared estimation error for thesecond device will be (1-1)²+(0-1.5)²=2.25. The third device location isperfectly estimated, with zero error, leading to a total error of 2.5.Other error measures may be considered as well, such as Sum of AbsoluteErrors, or weighted variations which may take other considerations intoaccount and/or add penalty factors to certain types of errors.

At step 137, the method may loop back to step 133, as the first row ofmeasurements has been fit to the first NIM, and other map rows have notbeen fit. At step 134, the first row of measurements is fit to thesecond NIM row, and at step 135, the other EL rows are “snapped” to theNIM and fitted to the other NIM rows, as shown in Fitting B. Thematching illustrated in Fitting B is less successful than the one shownin Fitting A, and the fitting error calculated in step 136 will behigher. At step 137, the method will determine that the first row ofmeasurements has not yet been fit to one of the NIM rows (the third),and it will loop back to step 133 and select the third NIM row. At step134, the first row of measurements may be fit to the third NIM row, andat step 135, the other EL rows may be “snapped” to the NIM and fitted tothe other NIM rows. Several fittings are possible, as illustrated byFitting C and Fitting D, and by various methods the algorithm can beconfigured to consider multiple fittings and select one of the fittings,for example, a fitting with minimal estimation error or a leastestimation error. At step 136 the fitting error will be calculated, andat step 137 the algorithm will determine that the first row ofmeasurements has now been fit to all of the NIM rows, and will proceedto step 138. At step 138, the algorithm will determine that Fitting Ahas the lowest estimation error of all the fittings considered, and willoutput Fitting A at step 139.

FIG. 3A is a flow diagram of a method for generating an installation mapbased on time and location according to one or more illustrative aspectsof the disclosure. In one or more embodiments, the method of FIG. 3A, orone or more steps thereof, may be performed by one or more computingdevices or entities. For example, portions of the method of FIG. 3A maybe performed by components of a computer system. The method of FIG. 3A,or one or more steps thereof, may be embodied in computer-executableinstructions that are stored in a computer-readable medium, such as anon-transitory computer-readable medium. The steps in the method of FIG.3A might not all be performed in the order specified and some steps maybe omitted or changed in order.

The method of FIG. 3A may be used for grouping device measurements intorows. For example, the method of FIG. 3A may be performed at step 132 ofFIG. 2A. According to this illustrative embodiment, each row of aninstallation may be processed such that the time that elapses betweenscanning a device in the row and the adjacent device in the row is lessthan a certain threshold, such as, for example, 10 seconds. Theinstaller may be instructed to scan each device in the row rapidly, andtake a short break between rows. The scanning device may be configuredto record the time each device was scanned.

At step 310, a time difference between each pair of consecutive scansmay be calculated. At step 320 the calculated time differences may becompared to a threshold amount of time. In some embodiments thethreshold may be preset or predefined, and in some embodiments thethreshold may be derived from calculated time differences (e.g., thethreshold may be twenty percent longer than an average time differencebetween consecutive scans). At step 330, if the time difference betweenthe timestamps of scanning two consecutive devices is above thethreshold, the two devices may be determined to be in different rows,and may be mapped to different rows at step 340. If the time differenceis below the threshold, the two devices may be determined to be in asame row, and mapped to the same row at step 350. Alternatively, or inaddition to the method described above, the installer may be instructedto press a “New Row” button on his or her device between rows, which mayindicate completing the scanning of one row and beginning another. The“New Row” button may be used to override timing considerations, and/orto compensate for inconsistent scanning speed.

FIG. 3B is a flow diagram of a method for mapping samples to stringsaccording to one or more illustrative aspects of the disclosure. In oneor more embodiments, the method of FIG. 3B, or one or more stepsthereof, may be performed by one or more computing devices or entities.For example, portions of the method of FIG. 3B may be performed bycomponents of a computer system. The method of FIG. 3B, or one or moresteps thereof, may be embodied in computer-executable instructions thatare stored in a computer-readable medium, such as a non-transitorycomputer-readable medium. The steps in the method of FIG. 3B might notall be performed in the order specified and some steps may be omitted orchanged in order.

Reference is now made to FIG. 3B, which shows an illustrativeimplementation for grouping device measurements into rows. For example,the steps described in FIG. 3B may be performed at step 132, describedabove in FIG. 2A. According to this illustrative embodiment, each row ofthe installation may be processed such that the distance and/or anglebetween scanned devices may be compared to a reference distance and/orangle. The scanning device may be configured to determine and/orestimate a global position at the time of each scan, by utilizinglocalization systems such as Global Positioning System (GPS). At step315, the estimated distance and/or angle between each pair of scanneddevices may be calculated. At step 325, the estimated distance and/orangle between scanned devices may be compared to a reference and/or athreshold. In some embodiments the reference may be predefined, while inother embodiments the reference may be derived from calculated distances(e.g., the reference may be the average distance between consecutivescans, with a threshold twenty percent longer than the reference, or thereference may be derived from the angles between consecutive scans, withan appropriate threshold).

At step 335, the distance and/or angle between two devices, which mayhave been scanned consecutively, are compared to the reference distanceand/or angle. If, at step 335, it is determined that the distance and/orangle are above the threshold, the two devices may be mapped todifferent rows, or strings, at step 345. If, at step 335, it isdetermined that the distance and/or angle are below the threshold, thetwo devices may be mapped to a same row, or string, at step 355.Alternatively, or in addition to the method described above, theinstaller may be instructed to press a “New Row” button on his or herdevice between rows, which may indicate him or her completing thescanning of one row and beginning another. The “New Row” button may beused to override distance and/or angle considerations, and/or tocompensate for inconsistent distances and/or angles between devices inthe same row.

Reference is now made to FIG. 4, which depicts one illustrativeembodiment of representing a Non-Identifying Map (NIM). Generation of arepresentation of an NIM may be included in installation mapping methodsincluding steps such as step 100 from FIG. 1, which is described above.A PV installation may be represented as a text file which containsinformation regarding the installation. For example, an NIM may berepresented by a text file which lists the rows in the installation, thenumber of devices in each row, and/or the distance between each pair ofdevices. Additional information such as absolute locations of somedevices, row orientation, angles and distances between rows, or otherinformation may be included in the NIM. The mapping method may includean appropriate parser to parse the text file and extract informationfrom the NIM to compare the scanned information to the NIM layout.

FIG. 5A is a flow-chart of generating a Non-Identifying Map. In one ormore embodiments, the method of FIG. 5A, or one or more steps thereof,may be performed by one or more computing devices or entities. Forexample, portions of the method of FIG. 5A may be performed bycomponents of a computer system. The method of FIG. 5A, or one or moresteps thereof, may be embodied in computer-executable instructions thatare stored in a computer-readable medium, such as a non-transitorycomputer-readable medium. The steps in the method of FIG. 5 might notall be performed in the order specified and some steps may be omitted orchanged in order.

FIG. 5A, depicts an illustrative embodiment of generation andrepresentation of a Non-Identifying Map (NIM). For example, the stepsdescribed in FIG. 5A may be performed during the method described inFIG. 1. A program or application may be used to design and plan a PVinstallation. The program may run on appropriate platforms (PCs,tablets, smartphones, servers, etc.), and may be made available toinstallers and/or system designers. The program may include a GraphicUser Interface (GUI) to facilitate in site planning. At step 101, thesite planner or designer may use the program or application to design aPV installation using the tools made available by the application. Forexample, FIG. 5B illustrates an example of a user interface for PVinstallation mapping that may be used at step 101 of FIG. 5A to designthe PV installation. A user may design a PV installation featuring aplurality of photovoltaic generators 501 (e.g. PV panels, PV modules, PVcells, strings or substrings of PV panels) and featuring one or morepower converters (e.g. PV inverter 502).

At step 102, of FIG. 5A, a binary file may be generated comprisinginformation describing a portion of or the full layout of the system.The binary file may be generated at step 102 after a layout of the PVinstallation has been designed using the program GUI. Embodiments of thePV installation mapping methods described herein may include a step 103of reading the binary file generated at step 102 and extracting sitelayout information from the binary file.

Reference is now made to FIG. 6, which shows components for scanning aPV device and logging the time and/or location of the scanner at thetime of scanning. PV device 602 (e.g. PV panel, optimization device,DC/DC converter, inverter, monitoring device, communication device,etc.) may be marked with an ID marker 600 that can be scanned orprocessed. ID marker 600 may be a barcode that can be scanned by ascanning device. ID marker 600 may be a serial number identifiable by acamera, such as a camera with digit-identification capabilities. IDmarker 600 may be an RFID tag, or a memory device readable by anelectronic circuit. It should be understood that any other type ofmarker may be used in addition to or instead of the listed examples.

Scanning and localization device 601 may capture or record data providedby the ID marker 600. For example, the device 601 may be configured toobtain the identifying information from PV device 602, by scanning,taking a picture of, or retrieving data stored by the ID marker 600.Device 601 may include a clock and memory device, and be configured tostore the timestamp of each scan along with the identifying informationof the device scanned at that time. Device 601 may include alocalization device such as a GPS device, configured to communicate withsatellites 603 and estimate the location of the device at the time ofscanning. In one implementation, the GPS methods employed may allow forestimates with sufficient accuracy to provide differentiation betweenadjacent PV devices deployed in the same installation.

Reference is now made to FIG. 7, which shows examples of scanning andlocating devices that can be used in conjunction with illustrativeembodiments described herein. Combined device 700 may include one ormore of the illustrated components. ID reader 203 may be configured toretrieve identifying information from a PV device. In some embodiments,ID reader 203 may comprise a camera, and may be configured to take aphotograph of a serial number or other identifying information on the PVdevice. In some embodiments, ID reader 203 may comprise a barcodescanner and be configured to scan a barcode on the PV device. In someembodiments, ID reader 203 may comprise an electronic circuit configuredto read an RFID tag or a memory device storing identifying information.

In some embodiments, the device 700 may include GPS device 201,configured to receive or determine a GPS location, for example, whenscanning a PV device. The device 700 may write (e.g. record, store,transmit, etc.) the ID information and GPS coordinates to data loggingdevice 202. The data logging device 202 may comprise flash memory,EEPROM, or other memory devices.

Controller 205 may synchronize the various components comprising device700. The controller 205 may comprise a DSP, MCU, ASIC, FPGA, and/or adifferent control unit. The controller may be split into several controlunits, each responsible for different components. Device 700 may includecommunication device 206. The communication device 206 may be configuredto communicate using a wireless technology such as ZigBee, Bluetooth,cellular protocols, and/or other communication protocols. In someembodiments, measurements, timestamps and/or ID information may betransmitted, for example, by the communication device 206, to a remoteserver and/or stored to memory at a remote location. Device 700 mayinclude clock 204, configured to sample, store, and/or communicate thetime (in conjunction with the memory device and/or communicationdevices). For example, the clock 204 may be used to record a timestampeach time the ID reader 203 determines (e.g. obtains, measures, etc.) adevice ID.

Device 700 may further include tilt sensor 207, configured to measurethe tilt of the device 700 and store the measurement to memory and/orcommunicate the measurement. The tilt sensor may be used to measure thetilt of PV devices such as PV panel. Scanning device 700 may alsoinclude a compass 208. The compass 208 may be configured to measure ordetermine the direction a PV module is facing. For example, the compass208 may be used to measure a direction of a PV module when a tiltmeasurement is carried out. Determining the tilt of one or more PVpanels and/or the direction that the one or more PV panels face may beuseful for various applications, such as monitoring applications ormapping applications. If the tilt of the PV panels is fixed duringdeployment, the installer may want to measure tilt and angle whilescanning the PV devices for mapping purposes. The scanned data may beuploaded to a remote monitoring device.

In some embodiments, a device such as mobile phone/tablet 710 mayinclude some or all of the functionality described with regard tocombined device 700. Combined device 700 may also include a screen,configured to display the information generated by the device. In oneimplementation, the screen may display information in real-time, whichmay allow the installer to monitor progress, and may improve scanningaccuracy. Many mobile devices include ID readers such as barcodescanners or a camera, a GPS device, controller, communication methods, aclock, compass and tilt sensor. Application software may be downloadedto the mobile device to allow the different components to interact in away that achieves the desired functions described herein with regard tomapping PV installations. The mobile device may allow the installationmap to be displayed on the device's screen while scanning, and showreal-time updating of the information attached to each PV device in thefield, to aid the installer in determining that the information is beingprocessed accurately and clearly.

FIG. 8A is a flow diagram of a method for installation mapping accordingto one or more illustrative aspects of the disclosure. In one or moreembodiments, the method of FIG. 8A, or one or more steps thereof, may beperformed by one or more computing devices or entities. For example,portions of the method of FIG. 8A may be performed by components of acomputer system. The method of FIG. 8A, or one or more steps thereof,may be embodied in computer-executable instructions that are stored in acomputer-readable medium, such as a non-transitory computer-readablemedium. The steps in the method of FIG. 8A might not all be performed inthe order specified and some steps may be omitted or changed in order.

Reference is now made to FIG. 8A, which shows an illustrative method forestimating relative positions of a plurality of PV devices with regardto one another. In one implementation, the position may be estimated, ordetermined, without the use of localization devices, such as satellites.All or a portion of the PV devices in a PV installation may be equippedwith a communication device, such as a wireless transceiver running anappropriate wireless protocol (e.g. Bluetooth, ZigBee, Wi-Fi, LTE, GSM,UMTS, CDMA etc.) or a Power-Line Communication (PLC) transceiver, whichmay be coupled to the PV installation's cables and configured tocommunicate by sending messages to each other over the cables.

At step 800, a mapping algorithm may be initialized by assigning randomlocations to each of the PV devices that are to be mapped. In oneimplementation, one or more of the devices may begin communicating bybroadcasting an ID number, the current timestamp, and/or otherinformation over the communication medium (e.g. power cables, wirelesschannels). For example, the ID number, timestamp, or other informationmay be transmitted at a predetermined amplitude. All or a portion of thedevices may be able to detect the ID signals that are broadcast by theother devices. The received signal strength and/or the time it takes forthe signal to propagate from one device to the next may depend on thedistance and signal attenuation between the devices. In someembodiments, the devices may engage in one-way communication only, i.e.each device might only send messages to some or all of the other deviceswithout being configured to receive a response from any particulardevice(s). In some embodiments, two or more devices may engage intwo-way communication (e.g. Device A sends a message to Device Brequesting a response, and measures the elapsed time between sending themessage and receiving the response).

At step 805, the signal strength of each signal received by each deviceand/or the time delay between sending and receiving messages may bemeasured. At step 810 the signal strength and/or time delay measured atstep 805 may be used to generate one or more initial estimates ofpairwise distances between devices. The initial estimates may compriseerror, such as error due to stochastic attenuation factors, noisychannels, and/or unexpected delays in signal propagation. In oneimplementation, multiple measurements may be taken and then averaged, orsome other function may be applied to the measurements. In thisimplementation, an initial accuracy of the measurements may be improvedby taking multiple measurements.

At step 815, the initial distance estimates generated at step 810 may beinput to an algorithm, which may analyze the initial pairwise distanceestimates and use them to generate an Estimated Layout Map (ELM). Manyalgorithms for this step may be considered, and in some embodiments,combinations of algorithms may offer accurate results. For example, aLeast Squares (LS) problem may be formulated to create an ELM whichminimizes the disparity between the pairwise estimated distances betweenvarious devices. A myriad of other methods, such as simulated annealing,Convex Optimization, Semidefinite Programming, or MultidimensionalScaling can be combined with transliteration and/or triangulationtechniques to obtain an estimated layout based on the measurements.

At step 820, it may be determined whether a non-identifying map (NIM) isavailable. If a NIM is available, the method may proceed to step 840. Atstep 840, the NIM and ELM may be input to a matching algorithm which mayincorporate elements of the method illustrated in FIG. 2A, and furtherdiscussed in FIGS. 2B-D, to match the identifying informationincorporated in the ELM to the device locations described by the NIM. Atstep 845 the matching algorithm may run, i.e., execute, and at step 850a map of the installation may be output which outlines the devicelocations along with ID information for each device. The map may be in aformat viewable on an appropriate device, such as a computer monitor,mobile phone, tablet, etc. The map may be represented digitally or in atextual format.

Alternatively, if no NIM is available at step 820, the algorithm mayproceed to step 825. At step 825 the method may seek “anchor devices”,i.e., a set of one or more specific devices which have known locations.If such anchors exist (or can be easily obtained by the installer),certain device IDs from the ELM may be matched to the known locations atstep 835, and the rest of the devices may be arranged around them, withthe final arrangement then output at step 850. If no anchor devicesexist or can be obtained, the algorithm may use the current solutionwithout further modification at step 830, proceed from step to step 850,and output the ELM “as is”, as a final map of the installation with IDinformation for each device. The method of FIG. 8A may be carried out bya centralized processing device which has access to the measurementstaken by some or all of the PV devices (e.g., a system inverterincluding a processing unit, communicatively coupled to the PV devicesso that the devices can communicate their measurements to the inverter).

Reference is now made to FIG. 8B, which illustrates different stages ofthe mapping algorithm depicted in FIG. 8A according to a certainillustrative embodiment. In this illustrative embodiment, forillustrative purposes, step 815 comprises two stages. The first stagemay include utilizing a mesh-relaxation technique, such as described in“Relaxation on a Mesh: a Formalism for Generalized Localization” by A.Howard, M. J. Mataric and G. Sukhatme (Proceedings of the IEEE/RSJInternational Conference on Intelligent Robots and Systems (IROS 2001),with the result of the first stage being formulated as a Least-Squaresproblem and input to a Least-Squares solving method (many of which canbe found online, such as the “leastsq” method packaged in the SciPylibrary for the Python programming language). 870 depicts the reallayout of the PV installation, with each device numbered (0-119) andlocated in its “real” place. The real layout depicted in 870 is notknown to the algorithm at the time of running, and is provided here forillustrative purposes. 880 depicts an example result of step 800, wherethe mapping algorithm has generated random location estimates for eachdevice. In this illustrative embodiment, RSSI indicators (in conjunctionwith estimated random signal attenuation factors) are used to estimatepairwise distances between each pair of devices, and the estimates areinput to an implementation of the “Relaxation on a Mesh” methodmentioned above, at a first stage of step 815. The resultant ELM isdepicted in 890, which includes some misaligned rows and a few deviceswhich deviate from their “real” location illustrated in 870. Theestimate depicted in 890 may then be input to the SciPy “leastsq”function, and a final, smooth, accurate ELM may be output, such as theoutput depicted in 895. It should be noted that the diamond-like shapeof the ELM of 895 is obtained because of unequally scaled X and Y axes.For example, if the axes in L4 were scaled equally, the shape may bethat of a rectangle, which may be similar to the real installation asillustrated in L1. In one implementation the ELM 895 illustrates anestimate at the end of step 815. In the example illustrated in FIG. 8B,the degree of symmetry present in the installation may reduce accuracyof the estimated layout. In certain instances, a PV installation mayinclude asymmetrical elements (e.g. some rows being shorter than other,such as in the system depicted in FIG. 2B) which may improve accuracywhen matching ELM elements to NIM elements. In certain instances,asymmetrical elements may result in improvements in algorithmicconvergence and accuracy.

Reference is now made to FIG. 9, which shows an illustrative PVinstallation comprising PV devices which may be described on a map ofthe installation. The installation may include a plurality of PV strings916 a. 916 b, to 916 n. The PV strings may be connected in parallel.Each PV string 916 a-n may include a plurality of PV devices 903. PVdevices 903 may be PV cells or panels, power converters (e.g. DC/DCconverters or DC/AC converters) coupled to or embedded on PV panels,monitoring devices, sensors, safety devices (e.g. fuse boxes, RCDs),relays, and the like, or any combinations thereof. Individual PV devices903 may be identical or might be different. The PV devices 903 may becoupled in series or in parallel. For example, each PV device 903 maycomprise a DC/DC converter or DC/AC inverter coupled to a PV panel andconfigured to operate the panel at a set or determined power point, suchas a maximum power point. Each DC/DC or DC/AC converter may convertinput PV power to a low-voltage, high-current output, and multipleconverters may be serially connected to form a string having highvoltage. In some embodiments, each PV device 903 may include DC/DC orDC/AC converter converting input PV power to a high-voltage, low-currentoutput, and multiple converters may be connected in parallel to form astring having high current.

The plurality of PV strings 916 a-n, which may be connected in parallel,may be coupled to the inputs of PV system grouping device 904. In someembodiments, PV system grouping device 904 may comprise a centralinverter configured to convert a DC input to an AC output. The AC outputmay be coupled to a power grid. In some embodiments, PV system groupingdevice 904 may comprise one or more safety, monitoring and/orcommunication devices. Each of the PV devices 903 and/or the groupingdevice 904 may include an ID tag such as a barcode, serial number and/ormemory or RFID card, that comprises identifying information.

In illustrative embodiments, it may be possible to match device IDs tophysical locations on a map by utilizing various methods describedherein. In some embodiments, it may be possible to match device IDs tophysical locations on a map by determining which devices are coupledserially to one another (i.e. which devices comprise each string),determining the order of the various strings and then determining theorder of the devices within each string.

FIG. 10 is a flow diagram of a method for grouping power devices intogroups according to one or more illustrative aspects of the disclosure.In one or more embodiments, the method of FIG. 10, or one or more stepsthereof, may be performed by one or more computing devices or entities.For example, portions of the method of FIG. 10 may be performed bycomponents of a computer system. The method of FIG. 10, or one or moresteps thereof, may be embodied in computer-executable instructions thatare stored in a computer-readable medium, such as a non-transitorycomputer-readable medium. The steps in the method of FIG. 10 might notall be performed in the order specified and some steps may be omitted orchanged in order.

Reference is now made to FIG. 10, which depicts a method for grouping PVdevices into strings. The method may be used to determine which devicesare serially connected to one another in systems such as the systemdepicted in FIG. 9. The method of FIG. 10, or one or more steps thereof,may be used to group devices into map rows, such as at step 132 of FIG.2A. The method may apply to a plurality of PV devices which are able tochange their output voltage, such as DC/DC converters, and report theiroutput parameters (e.g. voltage, current) to a system management unitcommunicatively coupled to some or all the PV devices.

At step 900, it may be determined that one or more power devices areungrouped. For example, initially, all power devices may be ungrouped.At step 910, a power device may be selected from the ungrouped powerdevices. The power device may be selected randomly. For example, anoptimizer, such as an optimizer coupled to a power generation source,may be selected. In one implementation, all or portions of step 910 maybe performed by an inverter. At step 920, the power device selected at910 may be instructed to decrease or increase an output voltage of thepower device. For example, a message may be sent to the power device,via PLC, wirelessly, or via other communications methods, to increase ordecrease the output voltage of the power device.

At step 930, the method may wait for power devices, such as ungroupedpower devices, to report operating points. For example, the powerdevices may send telemetries based on a schedule or at variousintervals. At step 940, operating points received from power devices,such as ungrouped power devices may be recorded. The operating pointsmay be responsive to the increase or decrease in output voltage that wasrequested at step 920.

At step 950, one or more devices that do not report a change in voltagemay be grouped with the power device selected at step 910. For example,devices that do not report a change in voltage greater than a thresholdchange in voltage may be grouped with the selected power device. Thethreshold may be preset or predetermined, or determined based onreceived operating points.

At step 960, it may be determined whether there are one or moreungrouped devices. If there are one or more ungrouped devices, themethod may return to step 910 and select one of the one or moreungrouped devices. Otherwise, if at step 960 it is determined that alldevices have been grouped, the method may proceed to step 970. At step970, the grouping may be considered complete, and the division ofdevices into groups may be output.

As an example of the method described in FIG. 10, assume PV systemgrouping device 904 is an inverter including a power-line-communications(PLC) or wireless transceiver and a processor, and each PV device is anoptimizer including a DC/DC converter, a maximum-power-point-tracking(MPPT) circuit and a PLC or wireless transceiver. Each optimizer may becoupled to one or more power generation sources such as PV panels,batteries and/or wind turbines. Before the grouping process begins, eachoptimizer may be configured to output a certain low, safe voltage suchas IV. Since the strings of optimizers (e.g. 316 a. 316 b) are coupledin parallel, they will maintain a common voltage between the two ends ofeach string. The optimizers may periodically send telemetries to the PVsystem grouping device 904 using PLC, where they report their currentoutput voltages. At step 900, the power devices (optimizers in thisexample) are ungrouped. At step 910, the inverter chooses a firstoptimizer at random (e.g. Optimizer A, belonging to String F), and atstep 920 sends a message (via PLC or wirelessly) instructing Optimizer Ato increase its output DC voltage. This increase in voltage results in acorresponding increase in the voltage of the string including the chosenoptimizer, String F. To maintain a common string voltage, the optimizersbelonging to all the other strings may increase their voltages as well.However, the optimizers which are part of String F (e.g. Optimizers B-K)might not increase their output voltage, as Optimizer A has alreadyraised its voltage. When the optimizers next send telemetries to theinverter, via PLC or wirelessly, at step 930. Optimizer A will report ahigh voltage, Optimizers B-K will report the same voltage as before, andall other optimizers will report increases in voltage. At step 940, theinverter processor will record the reports from all the optimizers. Atstep 950, the inverter will determine that all optimizers not reportinga significant change in voltage (B-K) belong to the same string as theoriginally selected optimizer (A), group them as a string and removethem from the “ungrouped power devices pool”. The algorithm then repeatssteps 910-50 until all optimizers have been grouped, at which stage itcomes to an end, at step 970 outputting the division of optimizers intogroups.

Reference is now made to FIG. 11A, which shows an illustrativeembodiment of a PV string of PV devices, where it may be possible todetermine the order of the devices within the string. Time DomainReflectometry (TDR) may be used to determine the ordering of PV deviceswithin a PV string. String 317 may comprise a plurality ofserially-connected PV devices 104, such as PV devices 104 a. 104 b, to104 k. The string 317 may comprise any number of PV devices 104 a-k.Devices 104 a-k may comprise elements similar to those previouslydiscussed with regard to PV devices 903. Devices 104 a-k may eachinclude power converter 210 (e.g. a DC/DC or DC/AC converter) whichreceives input from a PV panel, battery or other form of energygeneration, and produces an output. One output of converter 210 may becoupled to a variable impedance Z, and the other output may serve as thedevice output, to be coupled to an adjacent PV device in string 317. Inthis manner, string 317 may include a plurality of variable impedanceswhich are coupled to the cables which couple the PV devices to oneanother, forming the serial string. Each PV device 104 a-k may include acontroller 220, configured to control the value of variable impedance Z.Controller 220 may be the same controller used to control the othercomponents of PV device 104 a-k (e.g. power converter 210, communicationmodule 230, safety device(s) 240, auxiliary power 250, etc.), or it maybe a different controller. Transceiver 115 may be coupled to the string317, and may be configured to inject a voltage or current pulse over thestring and measure the reflected wave. The transceiver may be coupled toone of the edges of the string, or may be coupled to a middle pointbetween two devices. According to TDR theory, the waveform reflectedback to the transceiver depends on the characteristic impedance of thePV string line. The characteristic impedance of the PV string may beaffected by each of the variable impedances coupled to it, so by rapidlychanging the variable impedance on one of the serially connected PVdevices, a rapidly changing reflected waveform may be formed.

Reference is now made to FIG. 11B, which shows several examples ofvariable impedance configurations. Variable impedance 1110 may includeinductor L1, resistor R1, capacitor C1 and switch Q1 (e.g. a MOSFET),all connected in parallel. When switch Q1 is ON (e.g. by a controllerapplying an appropriate voltage to the gate of MOSFET) the totalimpedance of impedance 1110 may be zero, since the switch bypasses theother impedance elements. When switch Q1 is off, the impedance of 1110may be nonzero, and may be calculated as the impedance of the otherthree components connected in parallel. Variable impedance 1120 maycomprise inductor L2, resistor R2, capacitor C2 connected in parallel,inductor L22 coupled to them in series, and switch Q2 connected inparallel to the whole arrangement. Here, when Q2 is ON the equivalentimpedance of 1120 may be zero, and when it is OFF the impedance of 1120may be nonzero, and calculated as the impedance of R2, C2 and L2 inparallel added to the impedance of L22. Variable impedance 1130 featurestwo switches, Q3 and Q33, and more than two impedance levels. When Q3 isON, the impedance of 1130 is zero. When Q3 and Q33 are both OFF, theimpedance of 1130 is simply the impedance of inductor L3. When Q3 is OFFand Q33 is ON, the impedance of 1130 is the equivalent impedance ofinductor L3, resistor R3 and capacitor C3 all coupled in parallel.Obviously, many more arrangements of components may be utilized fordifferent (or additional) impedance levels. The switching of theswitches (Q1, Q2, Q3, Q33) may be controlled by an appropriatecontroller (e.g. DSP, MCU, FPGA etc.) within the relevant PV device.

Reference is now made to FIG. 12, which shows a waveform reflected froma PV string including variable impedances, according to illustrativeembodiments described herein. If illustrative variable impedances areswitched at a very high frequency (e.g. a frequency above 100 kHz, suchas hundreds of kilohertz, several megahertz, tens or hundreds ofmegahertz, or several gigahertz), a ripple may be detected on the wavereflected back to the transceiver. If several variable impedances arevaried on the same string, the ripple each impedance causes may appearat a different time, due to the difference in distance betweenimpedances. For example, if two PV devices including variable loads arespaced 1.5 meters apart, with one of the PV devices being 1.5 meterscloser to the transceiver than the other, the waveform transmitted bythe transceiver will travel an additional 1.5 meters to reach thefurther PV device, and the reflected wave will travel an additional 1.5meters as well on the way back, for a total difference of 3 meters inthe route. Assuming the waveforms travel at the speed of light, C=3·10⁸m/sec, the ripple caused by the farther variable impedance will appear

${\Delta\; t} = {\frac{3\lbrack m\rbrack}{3 \cdot {10^{8}\left\lbrack \frac{m}{\sec} \right\rbrack}} = {10\lbrack{ns}\rbrack}}$later than the ripple caused by the closer variable impedance.High-quality digital or analog sensors may be able to detect timedifferences at this resolution. For example, if transceiver 115 commandsdevice 104 b to vary its impedance, it may detect a ripple appearing onthe reflected waveform after 200 [ns]. If transceiver 115 commandsdevice 104 a to vary its impedance, and it detects a ripple appearing onthe reflecting waveform after 210 [ns], it may determine that device 104a is 1.5[m] further than device 104 b. By iteratively sending similarcommands to each device in the system, the transceiver unit may be ableto determine the relative distances of each PV device, and inconjunction with grouping the devices into strings and/or rows (usingmethods such as the illustrative embodiments shown in FIG. 10), thelocation of each device may be determined.

FIG. 13 is a flow diagram of a method for testing power devicesaccording to one or more illustrative aspects of the disclosure. In oneor more embodiments, the method of FIG. 13, or one or more stepsthereof, may be performed by one or more computing devices or entities.For example, portions of the method of FIG. 13 may be performed bycomponents of a computer system. The method of FIG. 13, or one or moresteps thereof, may be embodied in computer-executable instructions thatare stored in a computer-readable medium, such as a non-transitorycomputer-readable medium. The steps in the method of FIG. 13 might notall be performed in the order specified and some steps may be omitted orchanged in order.

Reference is now made to FIG. 13, which described an illustrative methodwhich may be used to determine the relative distances of seriallyconnected PV devices from a waveform-generating transceiver, in a systemwhich may be arranged similarly to the system shown in FIG. 11A. At step1320, one or more power devices may be defined as “untested”. i.e., theyhave not been commanded to vary their impedance. For example, initially,all power devices may be determined to be untested.

At step 1325, one of the untested devices is selected. For example, anuntested device may be selected randomly at step 1325. At step 1330, thedevice selected at step 1325 may be commanded to vary its variableimpedance. For example, the device may be commanded to vary its variableimpedance at a determined frequency, such as a high frequency. At step1335, a transceiver may transmit a voltage pulse over the PV string. Atstep 1340, the transceiver may receive the reflected wave, record and/ortime the response, and save the received or determined data to memory atstep 1345. At step 1350, the selected device may be removed from thepool of “untested” devices, and may be commanded, for example, by thetransceiver, to stop varying its output. At step 1355, the transceivermay check or determine if there are devices in the string which areuntested. If there are untested devices, the method may return to step1325, and another power device may be selected. If it is determined, atstep 1355, that all power devices have been tested, the method mayproceed to step 1360. At step 1360 the transceiver (or a master controlunit or other system which receives data from the transceiver) mayanalyze the saved reflected waveforms and time samples, determine (asexplained previously) which devices are closer than others, and estimatethe distances between devices.

Reference is now made to FIG. 14, which shows an illustrative PVarrangement. In PV arrangement 309, PV devices 105 a, 105 b, to 105 kare coupled in parallel to one another. Although not illustrated in FIG.14, the devices 105 a-k may be coupled in parallel to a system powerdevice such as an inverter, management and/or communication unit, safetydevice(s), or other devices. Each PV device 105 a-k may be coupled to apower source (e.g. PV panel, battery, wind turbine etc.) and may includea DC/DC or DC/AC converter configured to output a high-voltage DC or ACvoltage which is common to all PV devices 105 a-k coupled in parallel.In this illustrative system, devices 105 a-k might not be coupled inseries with one another. Transceiver 116 may be coupled to the PVdevices 105 a-k and may be configured to communicate with the devices105 a-k. It may be desirable for the system installer to know thedistances between the various devices and the transceiver, or to knowthe distance ordering (i.e. which device 105 a-k is closest, which isthe farthest, etc.). In parallel-connected embodiments, a voltage orcurrent pulse may be transmitted, with the PV devices 105 a-k takingturns varying their impedance as instructed by the transceiver 116, asexplained above in regards to FIGS. 11A-14. In this embodiment, thetransceiver 116 may analyze the current returning wave for disturbancescaused by the varying impedance circuits, and based on the time delay inrecording caused by each PV device, determine and/or list the devices105 a-k in order of distance from the transceiver 116.

Reference is now made to FIG. 15A, which depicts a PV device accordingto illustrative embodiments. PV panel 106 may include one or more solarcells on one side (not explicitly shown), and a lower portion of ajunction box 152 on a second side. A plurality of panel conductors 153such as ribbon wires may be coupled to the PV cells on one side of thepanel, and may protrude through slots in the lower junction box portion152 on the other side. The lower junction box portion 152 may befastened to the PV panel 106 at the time of manufacturing. Anidentification label (ID label) 151 may be attached to the panel 106 orlower junction box portion 152 either at the time of manufacturing orthereafter. The ID label 151 may be a barcode, serial number, RFID tag,memory device or any other medium for containing information that can beread by an external device. An upper junction box portion 150 may bemechanically attachable to the lower junction box portion, and mayinclude electronic circuits configured to receive PV power from theconductors 153, and may include string conductors 154 for coupling theupper portion to adjacent PV devices. In some embodiments, the upperjunction box portion 150 may be coupled to other upper box portions atthe time of manufacturing, using conductors of appropriate length toallow a plurality of upper portions 150 to be attached to a plurality oflower junction box portions during deployment in a PV installation. Theupper junction box portion 150 may include an appropriate device forreading the ID label 151 from the panel or lower junction box portion.For example, if the ID label 151 includes a barcode, the upper portion150 may include a barcode scanner. If the ID label 151 includes a serialnumber, the upper portion 150 may include a camera and be coupled to adevice configured to identify digits and/or letters. The upper portion150 may include an RFID tag reader, or a device configured to readidentifying information from a memory device. The upper portion 150 mayread, process and/or communicate the ID information automatically whenattached to the lower junction box portion 152. The upper junction boxportion 150 may also be configured with its own ID information, and beable to communicate to a management device both its own ID tag and theID label of the PV panel it is coupled to.

PV device ID tags may be used for several purposes. In some embodiments,the ID tags may be used to create a map of the PV installation includingthe locations of specific devices in the installation. In someembodiments, the tags may be used to authenticate PV devices and ensurethat approved devices are used in the installation, for example, byusing an authentication protocol. In some embodiments, the protocol maybe carried out by circuits and/or devices comprised in the upper part ofthe junction box. In some embodiments, the ID tag may be communicated toan external management device, and an authentication protocol may becarried out between components included in the lower portion, the upperportion and an external device or management unit.

Reference is now made to FIG. 15B, which shows an illustrativeembodiment of an upper portion of a junction box, such as the one thatmay be used in the arrangement depicted in FIG. 15A. Upper junction boxportion 150 may comprise power converter 245, which may be configured toreceive DC power from a PV panel and convert it to DC or AC power at theconverter outputs. Upper junction box portion 150 may comprise variableload 275. Upper junction box portion 150 may comprise an ID reader 285.Upper junction box portion 150 may further comprise controller 270 suchas a microprocessor, Digital Signal Processor (DSP) and/or an FPGA,configured to control some or all of the other functional blocks. Insome embodiments, the controller may be split into multiple controlunits, each configured to control one or more of the functional blocksof upper portion 150. Upper junction box portion 150 may compriseMaximum Power Point Tracking (MPPT) circuit 295, which may be configuredto extract power, such as a maximized power, from the PV module theupper portion 150 is coupled to. In some embodiments, controller 270 mayinclude MPPT functionality, and thus MPPT circuit 295 may not beincluded in the upper portion 150. Controller 270 may control and/orcommunicate with other elements over common bus 290. In someembodiments, the upper junction box portion may include circuitry and/orsensors 280 configured to measure parameters on or near a PV module orjunction box, such as voltage, current, power, irradiance and/ortemperature. In some embodiments, the upper junction box may includecommunication device 255, configured to transmit and/or receive dataand/or commands from other devices. Communication device 255 maycommunicate using Power Line Communication (PLC) technology, or wirelesstechnologies such as ZigBee, Wi-Fi, Bluetooth, cellular communication orother wireless methods. In some embodiments, the upper junction boxportion may include safety devices 260 (e.g. fuses, circuit breakers andResidual Current Detectors). The various components included in upperjunction box portion 150 may communicate and/or share data over commonbus 290.

FIG. 16 is a flow diagram of a method for grouping power devices intostrings. The method may be used to determine which devices are seriallyconnected to one another in systems such as the system depicted in FIG.9. The method of FIG. 16, or one or more steps thereof, may be used togroup devices into map rows, such as at step 132 of FIG. 2A. The methodmay apply to a plurality of power devices which are able to report theiroutput parameters (e.g. voltage, current) to a system management unitcommunicatively coupled to some or all of the power devices. Accordingto Kirchhoff's Current Law (KCL), serially coupled devices carry thesame current. According to KCL, if a plurality of serially-coupled powerdevices repeatedly report their output current to a system managementunit at substantially simultaneous times, the reported currents may besubstantially the same in magnitude. By logging the reported currentsover a period of time, it may be determined which power devices areunlikely to be serially coupled to one another (e.g. if two devicesreport currents which are significantly different at substantially thesame time, they are likely not serially coupled) and by a process ofelimination and application of an appropriate stopping condition, anaccurate estimate of the arrangement of power devices in a PV system maybe obtained.

At step 160, initial grouping possibilities may be considered. Forexample, each power device may be considered to be “possibly paired” toeach other power device in the system. In some embodiments, morelimiting initial possibilities may be considered based on priorknowledge. For example, it may be known that two power devices are notserially coupled to one another, and they may be initially considered“not paired.” In some embodiments, a counter may be optionally set totrack the number of iterations the method has run. At step 161, themethod may receive current measurements from two or more power devicesat substantially the same time.

At step 162, some of the current measurements may be compared to oneanother. For example, if Device A and Device B are considered “possiblypaired” at step 162 of the method, the current measurements of Device Aand Device B, I_(A) and I_(B), respectively, may be compared to eachother. If the current measurements are not substantially the same, theestimated relationship between Device A and Device B may be changed to“not paired.” In some embodiments, more than one instance ofsubstantially different currents may be required to change an estimatedrelationship to “not paired.” For example, Device A and Device B may beconsidered “possibly paired” until three pairs of substantiallydifferent current measurements have been reported. In some embodiments,the determination of whether currents are substantially the same isbased on an absolute current difference. For example, if |I_(A)−I_(B)|<ϵfor an appropriate ϵ (e.g. 10 mA, or 100 mA, or 1 A), then I_(A) andI_(B) might be considered “substantially the same.” In some embodiments,the determination of whether currents are substantially the same isbased on a relative current difference. For example, if

$\frac{{I_{A} - I_{B}}}{I_{B}} < {\alpha\mspace{20mu}{and}}$$\mspace{14mu}{\frac{{I_{A} - I_{B}}}{I_{A}} < \alpha}$for an appropriate α (e.g. 0.01, or 0.03, or 0.1) then I_(A) and I_(B)might be considered substantially the same. In some embodiments,multiple criteria may be used to determine if two currents aresubstantially the same.

By comparing pairs of current measurements to each other as detailedabove, it may be determined which devices are unlikely to be seriallycoupled to one another. In some embodiments, the method may comparecurrent measurements of each pair of power devices considered “possiblypaired.” and based on the result of the comparison, the method maychange the relationship between the pair of power devices to “notpaired.” In some embodiments, the method may compare only a portion ofthe current measurements to one another. In some embodiments, some orall the current measurements selected for comparison may be chosen atrandom.

At step 163, the method determines if a stop condition has been reached.In some embodiments, a stop condition may be reached when a certainnumber of iterations have been completed. The number of iterations whichtrigger the stop condition may be fixed (e.g. 10, 50, or 100), or maydepend on the number of power devices in the system (e.g. N/10, N/2 or√{square root over (N)} for a system containing N power devices). Insome embodiments, the stop condition may be triggered when a certainnumber of iterations have not changed the relationship between any twopower devices. For example, if three method iterations have not changedthe relationship between any two devices to “not paired,” the stopcondition may be reached. In some embodiments, the stop condition may bereached when each power device is considered “possibly paired” to nomore than a certain number of other devices. For example, a stopcondition may be reached if each power device is considered “possiblypaired” to no more than twenty devices, or forty devices, or sixtydevices. In some embodiments, a stop condition is reached based on acombination of criteria. For example, a stop condition may be reachedonly if three method iterations have not changed the relationshipbetween any two devices to “not paired,” and additionally, each powerdevice is considered “possibly paired” to no more than fifty devices.

If the method determines that the stop condition has not been reached,at step 165 the iteration counter may be incremented, and the method mayreturn to step 161. If the method determines that the stop condition hasbeen reached, the method may continue to step 164, and for each PowerDevice X, output the group of power devices that are considered“possibly paired” to Power Device X (i.e. the “potential group” of PowerDevice X).

Reference is now made to FIG. 17A, which shows an illustrativeembodiment of a PV string of PV devices, where it may be possible todetermine the order of the devices within the string. Selective couplingof PV devices to a common ground may result in leakage current, whichmay be used to determine the ordering of PV devices within a PV string.String 318 may comprise a plurality of serially-connected PV devices107, such as PV devices 107 a, 107 b, to 107 k. The string 318 maycomprise any number of PV devices 107 a-k. The string may be coupledbetween a ground terminal and a power bus. The voltage between theterminals of each PV device may vary from device to device. For example,in the illustrative embodiment depicted in FIG. 17A, PV device 107 aoutputs 25V, PV device 107 b outputs 30V (55V−25V=30V), and PV device107 k outputs 39.3V (700−660.7V=39.3V). The string voltage may be thesum of the voltages output by each PV device in the string, with thepower bus being at voltage approximately equal to the string voltage.

Devices 107 a-k may comprise elements similar to those previouslydiscussed with regard to PV devices 903 and/or 104. Some elements havenot been explicitly illustrated. Devices 107 a-k may each include powerconverter 211 (e.g. a DC/DC or DC/AC converter) which receives inputfrom a PV panel, battery or other form of energy generation, andproduces an output. The converter may include two output terminals forserial coupling to adjacent PV devices in string 318. One output ofconverter 211 may further be coupled to a leakage circuit 108 at leakageterminal LT. Leakage circuit 108 may be variously configured. In anillustrative embodiment such as shown in FIG. 17A, leakage circuit 108may comprise a serial branch including resistor R, switch Q andcurrent-sensor A1. The serial branch may be coupled to a commonelectrical ground. In some PV installations, the mounting structuresused to support PV panels may be required to be coupled to a commonground, and in such embodiments, the leakage branch may be coupled tothe ground via the mounting structures. In some embodiments, alternativegrounding points may be considered. Resistor R may be of largeresistance, such as 10 kΩ, 100 kΩ or even 1 MΩ or larger. Switch Q maybe implemented using an appropriate device such as a MOSFET. Duringregular operating conditions, switch Q may be in the OFF position,disconnecting leakage terminal LT from the grounding point. Switch Q maybe temporarily be switched to ON, allowing current to flow from theleakage terminal LT to the ground. In some embodiments, where switch Qand current sensor A1 may have negligible resistance, a current ofmagnitude approximately proportional to the voltage at leakage terminalLT may flow through the leakage circuit and be sensed by current sensorA1. For example, if the voltage at leakage terminal LT is 100V, and theresistor R is of resistance 100 kW, current sensor A1 will sense aleakage current of

$\frac{100\mspace{20mu} V}{100\; k\;\Omega} = {1\mspace{20mu}{{mA}.}}$In some embodiments, PV device 107 may include a communication devicefor transmitting leakage current measurements to a management deviceconfigured to use the current measurements for appropriate calculations(not illustrated explicitly). Controller 214 may be similar tocontroller 220 described with regard to FIG. 11A, and may further beconfigured to control the switching of switch Q. In some embodiments, aseparate controller may be dedicated to switching switch Q.Communication device 212 may be configured to communicate with othersystem power devices for sending or receiving commands or data. Forexample, communication device 212 may be configured to providemeasurements of a voltage or current at leakage terminal LT.Communication device 212 may be a wireless (e.g. a cellular, ZigBee™,WiFi™, Bluetooth™ or other wireless protocol) transceiver, or a wiredcommunication device (for example, a device using Power LineCommunications).

Returning to string 318, in some embodiments each PV device 107 maycomprise a leakage circuit similar to leakage circuit 108. Each devicemay include a current sensor corresponding to sensor A1, and eachcurrent sensor may sense a different current, with the magnitude eachsensed current indicating a proximity to the system power bus. Forexample, using the numerical example indicated in FIG. 17A, if each PVdevice 107 a, 107 b . . . 107 k includes a leakage circuit coupled tothe “low voltage” output of a power converter 211, and each PV deviceincludes an identical resistor R=100 kΩ, PV device 107 a may sense acurrent of approximately

$\frac{0\mspace{20mu} V}{100\; k\;\Omega} = {0\mspace{14mu}{A.}}$PV device 107 b may sense a current of approximately

$\frac{25\mspace{20mu} V}{100\; k\;\Omega} = {0.25\mspace{20mu}{{mA}.}}$PV device 107 c may sense a current of approximately

$\frac{55\mspace{20mu} V}{100\; k\;\Omega} = {0.55\mspace{20mu}{{mA}.}}$PV device 107 j may sense a current of approximately

$\frac{650\mspace{20mu} V}{100k\;\Omega} = {6.5\mspace{20mu}{{mA}.}}$PV device 107 k may sense a current of approximately

$\frac{660.7\mspace{20mu} V}{100\; k\;\Omega} = {6.607\mspace{20mu}{{mA}.}}$It may be observed that the closer a PV device is to the power bus, thehigher the magnitude of the sensed current may be, and in someembodiments, it may be possible to estimate the relative order of the PVdevices 107 a . . . 107 k with regard to the power bus by comparing thecurrent magnitude sensed by each PV device.

Reference is now made to FIG. 17b , which shows a leakage circuitaccording to an illustrative embodiment. PV device 1007 may be usedinstead of PV devices 107 in FIG. 17A. For example, PV devices 107 a-107k of FIG. 17A may be replaced by a corresponding plurality of PV devices1007 a-k. PV device 1007 may comprise controller 214, power converter211 and communication device 212, which may be the same as controller214, power converter 211 and communication device 212 of FIG. 17A. PVdevice 1007 may feature a leakage terminal (LT) similar to that of PVdevice 107. Leakage circuit 1008 may comprise voltage sensor V1 andresistors R1 and R2. Resistor R2 may have a very large resistance, suchas 100 MΩ, 1 GΩ, 2 GΩ or even 10 GΩ. R1 may be substantially smallerthan R2. For example, R1 may have a resistance of under % 1 of R2. Ahigh-impedance current path may be provided between leakage terminal LTand the ground, via resistors R1 and R2. R1 and R2 may be of sufficientresistance to hold leakage current to a small value, which may reducelosses due to the leakage current. For example, R2 may be 5 GΩ and R1may be 10 MΩ, for a total resistance of 5.01 GΩ. If the voltage at LT is500V, the leakage current will be about 100 μA. Voltage sensor V1 maymeasure the voltage across resistor R1. Since R2 may be much larger thanR1, R2 may absorb the majority of the voltage drop at leakage terminalLT. As an illustrative example, assume that R2 is 99 times as large asR1, resulting in R2 absorbing 99 percent of the voltage drop at LT, andR2 absorbing 1 percent of the voltage drop at LT. If a series of PVdevices 1007 are serially coupled, each having a leakage terminal and aleakage circuit 1008, each respective voltage sensor V1 of eachrespective leakage circuit 1008 will measure a voltage equal to about %1 of the voltage at the respective leakage terminal. By determining arelative order in magnitude of the respective voltage measurements, anorder of the serially-coupled PV devices 1007 may be determined (e.g. bya centralized controller which may receive the voltage measurementsmeasured by the respective voltage sensors).

FIG. 18 is a flow diagram of a method for determining the order of powerdevices within a PV string, which may be similar to the PV stringillustrated in FIG. 17A. At step 170, some power devices may beconsidered “unsampled,” i.e. power devices at which leakage currentshave not been sampled. At step 171, a power device from a group ofunsampled devices may be selected. In some embodiments, a device may beselected from a group of unsampled devices at random. In someembodiments, a device may be selected from a group of unsampled devicesaccording to predetermined criteria, such as according to an estimatedlocation within a PV string. At step 172, a power device selected atstep 171 is commanded to activate the power device's leakage circuit. Apower device command may be received via various communication methods,for example PLC and/or wireless communications, and the command may besent by a system management unit. At step 173, upon reception of acommand to activate a leakage circuit, a power device's leakage circuitmay be activated. A leakage circuit may be similar to the oneillustrated in FIG. 17A, and an activation of a leakage circuit maycomprise setting the switch Q to the ON position. A current sensorsimilar to the sensor A1 illustrated in FIG. 17A may measure a leakagecurrent obtained when Q is at the ON position. At step 174, a leakagecurrent may be measured and the measurement may be saved to a datalogging device. The data logging device may comprise flash memory,EEPROM or other memory devices. At step 175, the power device selectedat step 171 may be removed from the pool of unsampled devices, and acommand may be issued to the power device to deactivate the powerdevice's leakage circuit. Deactivation may comprise setting the switch Qto the OFF state. At step 176 the method may determine if additionalpower devices are to be sampled. In some embodiments, the method willsample the leakage current of each power device in the string, and aslong as there is at least one power device which has not yet activatedits leakage circuit, the method will loop back to step 170. In someembodiments, may method may proceed to step 177 even if some powerdevices have not yet activated their respective leakage circuits. Atstep 177, the logged leakage current measurements may be compared, andbased on the measurements, a relative order of power devicescorresponding to the leakage current measurements may be estimated. Forexample, if three leakage currents have been measured, for exampleI_(A), I_(B), I_(C), with the three current measurements correspondingto power devices D_(A), D_(B), D_(C), and if I_(A)<I_(B)<I_(C), then themethod may determine that D_(C) may be the closest device of the threeto the power bus, and that D_(A) may be the farthest of the threedevices from the power bus. If leakage currents of all power devices ina PV string have been sampled, it may be possible in some embodiments todetermine the order of all of the power devices in the string.

Reference is now made to FIG. 19, which illustrates a portion of aphotovoltaic installation and a mapping Unmanned Aerial Vehicle (UAV)according to an illustrative embodiment. Photovoltaic (PV) installation199 may comprise PV modules 191. One or more Unmanned Aerial Vehicles(UAV) 190 may be used to obtain Estimated Layout Map (ELM) of PVinstallation 199, i.e., to determine the relative order and/or locationof PV modules 191. PV modules 191 may comprise PV generators (e.g. oneor more PV cells, PV strings, PV substrings, PV panels, PV shingles,etc.) coupled to photovoltaic power devices (e.g. PV optimizers, DC/DCconverters, DC/AC inverters). In some embodiments, each PV module 191may comprise an identification label (ID label) which may be readable byUAV 190. The ID label may be a barcode, serial number, RFID tag, memorydevice or any other medium for containing information that can be readby an external device, with UAV 190 comprising an appropriate device forreading the ID label. For example, each PV module 191 may have an RFIDtag, while UAV 190 may have an RFID reader. In some embodiments, each PVmodule 191 may have a barcode sticker, tag, while UAV 190 may have abarcode scanner. UAV 190 may have various functional devices similar tothose comprising combined device 700 of FIG. 7. For example, UAV 190 maycomprise controller 195, communication device 196, GPS device 194, IDreader 193, and data logging device 192, which may be similar to or thesame as ID reader 203, GPS device 201, data logging device 202,controller 205, and communication device 206 of FIG. 7.

In some embodiments, UAV 190 may automatically read the ID tag of eachof PV modules 191. In some embodiments, UAV 190 may be in proximity toeach PV module at the time the PV module's ID tag is read, and use GPSdevice 194 to estimate the coordinates of the PV module being scanned.The method of FIG. 2A may be used to generate an ELM of the PVinstallation using the measured or estimated GPS coordinates of the PVmodules.

UAV 190 may be variously realized. For example, a drone, miniaturehelicopter, remote-controlled airplane or various other UAVs may beutilized.

In some embodiments, UAV 190 may comprise a thermal camera. For example,camera 197 may be a thermal camera for obtaining a thermal image of PVinstallation 199, and by taking multiple thermal images of PVinstallation 199 over time, relative locations of PV modules may beestimated for generating an ELM, using methods disclosed herein.

Reference is now made to FIG. 20, which illustrates thermal propertiesof photovoltaic generators (e.g. photovoltaic panels) which may befeatured in accordance with methods and apparatuses disclosed herein.Some types of photovoltaic panels may generate increased heat whenphotovoltaic power generated by the panel is not provided to anelectrical load. Photovoltaic power may be generated by a PV panel as aresult of photovoltaic cells mounted on the PV panel absorbing solarirradiance. When an electrical load is coupled to a PV panel, some ofthe absorbed solar irradiance may be converted to electrical powerprovided to the load. If no electrical load (or a reduced electricalload) is coupled to the PV panel, an increased portion of the absorbedirradiance may be converted to heat, which may result in an increasedtemperature of the PV panel. If an electrical load is coupled to a PVpanel, but the load only draws a small portion of the PV power producedby the panel, the panel temperature may be lower than the temperaturewhen compared to the “no-load” case, but may be higher than thetemperature that would be measured if an electrical load drew anincreased amount of PV power from the PV panel.

FIG. 20 illustrates an illustrative thermal image of a group of PVgenerators (which may be used as PV modules 191 of FIG. 19). PVgenerators 2001 b may be providing a first level of electrical power(e.g. 300 watts) to a load, PV generators 2001 c may be providing asecond level of electrical power (e.g. 200 watts) to an electrical load,and PV generators 2001 may be providing a third, lower level ofelectrical power (e.g. 50 W) to an electrical load, or might not beproviding any electrical power to a load. All of PV generators 2001a-2001 c may be irradiated by substantially the same level of solarirradiance. As indicated by temperature bar 2002, a reduced provision ofelectrical power to a load may increase a temperature of an associatedPV generator in a manner (e.g. by about 4° C.) which may be visuallydetectable by a thermal image.

Reference is now made to FIG. 20, which illustrates a thermal imageportion of a photovoltaic string according to an illustrativeembodiment. PV panels 2001 a-2001 f may be coupled in series or inparallel to form part of a PV string. At the time the thermal image wasobtained, PV panels 2001 a-2001 e were coupled to an electrical load,and PV panel 2001 f was not coupled to an electrical load. PV panel 2001f may be observed to be visually distinguishable compared to PV panels2001 a-2001 e.

Referring back to FIG. 19, camera 197 may be used to obtain thermalimages similar to the thermal images illustrated in FIGS. 20A-20C, withcontroller 195 configured to implement a method for determining a ELMfrom images obtained by camera 197. A succession of thermal imagessimilar to the images of FIGS. 20A-20C may be obtained and stored indata logging device 192, with controller 195 configured to read theimages from data logging device 192 for processing.

Reference is now made to FIG. 21, which illustrates a method forinstallation mapping according to one or more illustrative aspects ofthe disclosure. Method 2100 may be carried out by a controller comprisedby a UAV (e.g. controller 195 of FIG. 19), or by a system-levelcontroller in communication with PV modules and/or a UAV, or by acombination thereof. For illustrative purposes, it will be assumed thatmethod 2100 is carried out by controller 195 of FIG. 19 and applied toPV modules 191 of FIG. 19. Each PV module 191 may comprise a PV powerdevice capable of increasing or decreasing the electrical power drawnfrom the PV model. For example, in some embodiments, each PV module 191may comprise a disconnect switch configured to disconnect the PV modulefrom a string of PV modules which coupled to an electrical load. Bydisconnecting a selected PV module from the string of PV modules, theselected PV module may cease providing power to the electrical load, andthe temperature of the selected PV module may rise. In some embodiments,each PV module 191 may be coupled to an optimizer, each optimizerconfigured to increase or reduce the power drawn from the correspondingPV module.

PV power devices coupled to PV modules 191 may be in communication witha controller carrying out method 2100 or part thereof. For example, PVpower devices coupled to PV modules 191 may comprise wirelesscommunication devices configured to communicate with communicationdevice 196 of UAV 190.

Method 2100 may be applied to a group of PV modules without regard forinterconnectivity. Method 2100 may effectively map PV modules which areelectrically connected (e.g. modules which are part of the same PVstring) and may effectively map PV modules which are not electricallyconnected (e.g. modules which are part of different PV strings).

At the start of method 2100, at step 1220, all PV modules in the groupare considered “untested”. At step 1221, a controller (i.e. thecontroller carrying out method 2100 or part of method 2100) may select aPV module from the pool of untested PV modules. At step 1222, thecontroller reduces the electrical power drawn from the selected PVmodule. For example, the controller may command a PV power device (e.g.a disconnect switch or an optimizer) coupled to the PV module to reducethe electrical power drawn from the PV module (e.g. by disconnected thePV module from a load, or by operating the PV module at an operatingpoint which reduces the power drawn from the PV module.

After the electrical power drawn from the PV module is reduced, it maytake several minutes for the temperature of the PV module tosubstantially rise. The controller may wait for a period of time (e.g.3, 5, 10 or 20 minutes) before proceeding to step 1223.

At step 1223, the controller may control a thermal imaging device (e.g.camera 197) to obtain a thermal image of the group of PV modules. Atstep 1224, the controller may analyze the thermal image to find “hotspots”, e.g., areas in the image which indicate a higher temperature. Insome embodiments, the thermal image may comprise temperaturemeasurements which may be numerically compared. In some embodiments, thethermal image may be represented by pixels of varying colors and/orshades of gray, with the controller configured to process the image anddetect areas comprising pixels which may be indicative of a highertemperature (e.g. red, or darker shades of gray).

At step 1225, the controller may estimate the relative location of a hotspot detected at step 1224. For example, the controller may determinethat the group of PV modules comprises nine PV modules placedside-by-side (e.g. similar to the depiction of FIG. 20C), with thefourth PV module from the right (i.e. PV module 2001) hotter than therest. In some embodiments, the controller may have estimated physicalcoordinates of one of the PV modules, and may use the estimatedcoordinates as an “anchor” node for estimating locations of the other PVmodules. In some embodiments, the controller may determine a relativeordering or relational placements (e.g. to the right of, to the left of,in front of, behind) of the PV modules in the group, and aggregate therelational placements to generate a ELM.

In an embodiment, method 2100 may be adapted to have all PV devicesinitially not providing substantial power to an electrical load. Themethod may be adapted at step 1222 to increase the electrical powerdrawn from the selected PV module, at steps 1224-1225 to detect andestimate “cold spot” locations, and at step 1226 to decrease theelectrical power drawn from the selected PV module.

At step 1226, the PV module selected at step 1221 is removed from thegroup of untested PV modules, and the power drawn from the selected PVmodule is increased (e.g. by commanding a disconnect switch to reconnectthe PV module to an electrical load, or commanding an optimizer tooperate the PV module at an increased-power operating point).

At step 1227, the controller determines if untested PV modules remain,i.e., if there are PV modules in the group which have not yet beenselected at step 1221. If untested PV modules remain, the controller mayloop back to step 1221. If no untested PV modules remain, the controllermay proceed to step 1228.

At step 1228, the controller may aggregate the hot spot locationsestimated at step 1225 over the method iterations, to produce anestimated ELM.

In an alternative embodiment, thermal images obtained at step 1223 maybe saved to memory, with steps 1224-1225 carried out after the finaliteration of step 1227. In other words, analysis of thermal images maybe delayed until after a full set of thermal images (one per iterationthrough steps 1221-1227) has been obtained. In a preferred embodiment,steps 1224-1225 are carried out in the order indicated in FIG. 21, toenable the controller to repeat iterations if needed. For example,method 2100 may comprise an additional step of ensuring that a “hotspot” has been detected at step 1224, and in the event that the methodhas not identified a hot spot in the thermal image obtained at step1223, having the method loop back to step 1221, or alternatively, waitan additional several minutes and then loop back to step 1223.

Method 2100 may be combined with other methods disclosed herein, forexample, to increase the accuracy of ELMs and PIMs generated by methodsdisclosed herein. For example, method 2100 may be used to obtain aninitial ELM, with the method of FIG. 18 used for validation (orvice-versa).

In some embodiments, reference was made to “upper” and “lower” junctionbox portions. This language was used for ease and is not intended to belimiting. In some embodiments, the two portions may be side-by-side,and/or functional circuitry may be transferred from one junction boxportion to other, in a manner that allows them to be in electricalcommunication when coupled to one another.

In the illustrative embodiments disclosed herein, PV modules are used toexemplify energy sources which may make use of the novel featuresdisclosed. In some embodiments, the energy sources may includebatteries, wind or hydroelectric turbines, fuel cells or other energysources in addition to or instead of PV modules. The current routingmethods and other techniques disclosed herein may be applied toalternative energy sources such as those listed above, and thementioning of PV modules as energy sources is for illustrative purposesonly and not intended to be limiting in this respect. For example, anyother energy sources or combination of energy sources may be used.

It is noted that various connections are set forth between elementsherein. These connections are described in general and, unless specifiedotherwise, may be direct or indirect; this specification is not intendedto be limiting in this respect. Further, elements of one embodiment maybe combined with elements from other embodiments in appropriatecombinations or subcombinations.

What is claimed is:
 1. A method comprising: commanding a first powerdevice having output terminals to change an output electrical parameter;receiving output parameters reported by a plurality of power devices;and determining, by analyzing the output parameters, which power devicesof the plurality of power devices are serially coupled to the firstpower device.
 2. The method of claim 1, wherein each of the plurality ofpower devices comprise a DC/DC converter or a DC/AC converter.
 3. Themethod of claim 1, wherein one or more of the power devices seriallycoupled to the first power device are configured to maximize anelectrical parameter of one or more photovoltaic (PV) modules coupled tothe one or more power devices serially coupled to the first powerdevice.
 4. The method of claim 1, wherein the commanding and thereceiving comprise using wireless technologies.
 5. The method of claim1, wherein the commanding and the receiving are carried out overconducting electrical lines.
 6. The method of claim 1, furthercomprising: selecting a second power device and a third power devicefrom the plurality of power devices; varying a first impedance coupledto the second power device; varying a second impedance coupled to thethird power device; injecting, using a pulse source, a voltage orcurrent pulse over a power line coupled to the second power device andthe third power device; measuring a response of a reflected wavecorresponding to the pulse; and determining a relative proximity of thefirst impedance and the second impedance to the pulse source.
 7. Themethod of claim 6, wherein the first impedance and the second impedanceare varied at a frequency of greater than 100 kHz.
 8. The method ofclaim 6, wherein the first impedance and the second impedance are variedat different times.
 9. The method of claim 6, wherein the firstimpedance and the second impedance each comprise a switch that is turnedON and OFF.
 10. A power device comprising: a variable impedance; acommunication module; and a controller, wherein the communication moduleis configured to receive a message commanding the controller to vary animpedance of the variable impedance, and the controller is configured tovary the impedance of the variable impedance responsive to thecommunication module receiving the message.
 11. The power device ofclaim 10, wherein the controller is configured to vary the impedance ata frequency of greater than 100 kHz.
 12. The power device of claim 10,wherein the variable impedance comprises at least one inductor and atleast one capacitor.
 13. The power device of claim 10, wherein thevariable impedance comprises at least one switch.
 14. The power deviceof claim 10, wherein the power device further comprises at least one ofa DC/DC converter or a DC/AC converter.
 15. The power device of claim10, further comprising a junction box of a photovoltaic generator,wherein the variable impedance, the communication module and thecontroller are integrated in the junction box.
 16. A system comprising:a plurality of power sources; a plurality of power devices, each powerdevice coupled to a respective power source of the plurality of powersources, wherein the plurality of power devices are connected to form aserial string; and a system power device coupled to the serial string,wherein the system power device is configured to signal, via acommunication device, a selected power device of the plurality of powerdevices to increase an electrical parameter output by the selected powerdevice.
 17. The system of claim 16, wherein the system power device isconfigured to receive output parameters reported by the plurality ofpower devices and to determine, by analyzing the output parameters,which power devices of the plurality of power devices are seriallycoupled to the power device.
 18. The system of claim 16, wherein thesystem power device comprises a DC/AC converter.
 19. The system of claim16, wherein each of the plurality of power devices comprises a DC/DCconverter.
 20. The system of claim 16, wherein the electrical parameteris voltage.